1. Field of the Invention
The invention relates generally to the fields of hydrocarbon exploration, sedimentary basin simulation, subsurface hydrocarbon reservoir charge modeling, geological modeling, subsurface rock formation petrophysical properties evaluation and downhole fluid analysis. More specifically, the invention relates to techniques for integrating a plurality of different types of measurements of subsurface rock formations and related interpretation methods to evaluate probable spatial distribution and variations thereof of hydrocarbons within a sedimentary basin. A purpose for such evaluation is to reduce uncertainty during the exploration and appraisal of oil and gas reservoirs.
2. Background Art
A geologic sedimentary basin is a depression in the surface of the Earth's crust that undergoes infilling with sediment deposits. Such sediments are typically derived from weathered rock formations, from biogenic activity, from precipitation of minerals from solution and combinations of the foregoing. When deposited sediments are buried, they are subjected to increasing pressure and temperature. Such burial and subjecting to elevated pressure and temperature begin the process of lithification (conversion of unconsolidated sediments into rock formations).
Petroleum (i.e., oil and gas) may be formed within a basin by chemical reactions of sedimentary biogenic precursor material. After generation, petroleum is spatially distributed within the basin via permeable pathways until it accumulates within porous and permeable reservoir rock formations or it is dissipated by chemical or biochemical reactions, or leakage to the surface of the basin. Within any particular basin, there may be one or more “plays” for possible production of hydrocarbons. The U.S. Geological Survey defines a “play” as “a set of discovered or undiscovered oil and gas accumulations or prospects that exhibit nearly identical geological characteristics such as trapping style, type of reservoir and nature of the seal”. An accumulation may consist of several different reservoirs which differ from each other by the nature of the fluids within the pore spaces of the rock formations and/or the pressure thereof. Finally, a “reservoir” is defined as a rock formation with substantially uniform rock mineral properties and spatial distribution of permeability such that the rock formation has the capability to store fluids, and has the capability for fluids to be moved therethrough by application of suitable pressure variations.
Basin modeling is a technique that provides for reconstruction of geological processes that may have occurred in sedimentary basins over geological times, and more specifically the events leading to generation, migration and accumulation of hydrocarbons in reservoir rocks. Important inputs to basin modeling are the “charge” (source rock fractional hydrocarbon precursor content, source rock thickness, and hydrocarbon maturity), and the trap (the basin geometry, reservoir and seal qualities) of a prospect or play. The thermal, pressure and hydrocarbon generation and migration history are also modeled to make predictions of current hydrocarbon quality and spatial distribution within the basin. The description of petroleum fluids in basin modeling is primarily determined by the processes of generation and expulsion that govern the overall composition of the fluids, and the pressure, volume and temperature (“PVT”) behavior responsible for the distribution of components in each fluid phase during secondary migration and accumulation in a reservoir. The charge history of an accumulation or an individual reservoir can be tracked in compositional form according to selected compound classes, for example, CO2, H2S, methane, C2-5, C6-15, C16+. Thermodynamic models known as equations of state, e.g., SRK and Peng-Robinson, can be used to make phase property predictions such as gas-oil ratio (GOR), fluid density and/or fluid viscosity. Post-accumulation alteration processes such as biodegradation, water washing, and oil-to-gas cracking can also be simulated. Source rock tracking, the evolution of the composition through time, yields and compositions of the products generated and released can also be modeled. These simulations can be performed using a commercially available basin simulation software package, for example, one sold under the trademark PETROMOD, which is a registered trademark of Western Geco, LLC, 10001 Richmond Avenue, Houston, Tex. 77042. The foregoing software has the capability for the user to modify fluid data to calibrate the fluid model. Hydrocarbons are described in the basin simulation software using a limited number of components, e.g. up to 14 components. It is also customary to lump several components into one or more pseudo components (e.g. C2-C6, C15+) to reduce computation time.
The present day hydrocarbon composition depends chiefly on the quality of the precursor organic matter (the kerogen) and the processes of petroleum generation within the source rock. The controlling mechanisms for the formation of the hydrocarbons are the petroleum generation potential of the source rock, determined by the total organic (non carbonate) carbon (TOC) and the hydrogen index (HI), and the burial history, which determines the temperature history, and that regulates the multitude of chemical reactions that take place over geologic time to transform the kerogen into petroleum components. For example, one means of describing the petroleum generation process is by Arrhenius type reaction schemes. In such case, the model parameters are the Activation Energy, which describes the required threshold energy required to initiate the reaction, and the Frequency Factor (also known as pre-exponential factor), which represents the frequency at which the molecules will be transformed. Since many reactions take place, there could be several activation energy and frequency factor values. It is common practice to consider the frequency factor as constant due to its weaker dependence on temperature, and to represent the activation energy by means of a discrete probability distribution. The corresponding frequency factors and activation energies can roughly be determined by the organofacies, i.e. an empirical description of the type of the precursor material, concentration, depositional processes, and its relation to present day hydrocarbon composition. Hydrocarbon generation models are based on the analysis of source rock samples or on suitable geological assumptions about the history of a sedimentary basin. Such models consist of a distribution of organofacies, with appropriate frequency factors and activation energies. and the amount of precursor material, which is usually specified by means of TOC and HI maps.
The spatial extent covered by typical basin models is larger than for reservoir simulation models. Therefore, the spatial resolution of basin models is typically lower than that required for reservoir simulation. Some post-migration processes that affect the quality of the hydrocarbon, such as biodegradation and water washing, are better modeled at the basin scale; however, another important process that occurs at the reservoir scale and that affects the production of hydrocarbons from any particular reservoir is the mixing of hydrocarbon species. Typically the nature of the hydrocarbons generated in the source rock varies with time, a result of the burial and thermal history of the basin. Longer chain hydrocarbons (heavy components) are expelled first followed by shorter chain hydrocarbons (lighter components). It has been common practice in basin modeling to presume that fluid composition is homogenous throughout the accumulation, i.e., the chemical components are well mixed throughout the hydrocarbon column. However, in addition to biodegradation and temperature gradients, variations in fluid composition within an accumulation can be a result of the charge history and could even reflect active charging. See, for example, Mullins, O. C., Elshahawi, H., Stainforth, J. G., Integration of Basin Modeling Considerations with Wireline Logging, SPWLA 49th Annual Logging Symposium, Edinburgh, Scotland, May 25-28, 2008 and J. G. Stainforth, New Insights into Reservoir Filling and Mixing Processes in J. M. Cubit, W. A. England, S. Larter, (Eds.) Understanding Petroleum Reservoirs: toward and Integrated Reservoir Engineering and Geochemical Approach, Geological Society, London, Special Publication, (2004).
It is important to translate the present distribution of hydrocarbons in an accumulation to relevant parameters in the basin model that will help reduce uncertainty as to the spatial distribution of hydrocarbon species. Fluid properties are one of the key elements of basin modeling since they are a direct consequence of the series of events that took place over geologic time from the origin of the hydrocarbon. One way to determine fluid properties is by lowering a sample taking instrument into a wellbore drilled through the relevant rock formations and withdrawing a sample of the fluid from the rock formation under particular conditions. The foregoing technique enables the acquisition of fluid samples very close to the native reservoir pressure and temperature, therefore maximizing the likelihood that the samples are representative of the fluid existing in the particular reservoir. Furthermore, some analyses of the fluid in subsurface formations can be performed as it enters the sample taking instrument, minimizing the risk of sample fouling and providing a device for identifying the fluid that can be used for tracking the sample during subsequent analyses in the laboratory. Certain fluid features such as H2S, CO2, and asphaltene content are preferably determined in the downhole to avoid irreversible transitions during the sample transportation to the laboratory that lead to inaccurate measurements. Samples can be taken by such instruments at several depths along the wellbore, therefore the foregoing technique can provide the level of spatial resolution required to resolve fluid composition variations at the reservoir scale. Methods used for the analysis of reservoir fluids in the wellbore include visible-near-infrared absorption spectroscopy, gas chromatography, mass spectroscopy, nuclear magnetic resonance (NMR), and other sensors, to determine composition (e.g. fractional amounts of CO2, H2S, C1, C2, C3, C4, C5, C6, etc.), gas-oil ratio, distribution of hydrocarbon fractions based on carbon number and compound classes (saturates, aromatics, resins, paraffins, naphtenes, and asphaltenes), fluid density, fluid viscosity, saturation pressure, and identification of certain biomarkers. Density and viscosity of fluid samples may be measured in the downhole sampling tool at different pressures to obtain a better characterization of the PVT behavior of the fluid. The foregoing technique also enables reliable assessment of asphaltene content in petroleum. Another technique based on nuclear magnetic resonance enables an analysis of the fluids within the rock to estimate distribution of hydrocarbon fractions based on carbon number, gas-oil ratio, and relative ratios of hydrocarbon compound classes. Combination of both in situ analysis and analysis of the fluid as it is withdrawn into the sample taking instrument allows a more complete characterization of the fluid and provides immediate results that can be used to optimize the data acquisition process while the sampling tool is still in the well. The fluid properties that can be determined by the foregoing analyses are consistent with the level of detail of the fluid information required for basin simulation.
High-resolution laboratory measurements provide additional details on the chemistry of the downhole fluid samples also relevant for basin modeling. Such techniques include high field 13C and 1H nuclear magnetic resonance, high resolution mass spectroscopy, two-dimensional gas chromatography (GC×GC), sulfur X-ray absorption near edge structure (XANES) and carbon X-ray Raman spectroscopy. The results obtained with these techniques may be combined with the downhole fluid analyses for probing further on the nature of the fluids, comparing samples (compositional variations), identifying sample source, identifying post-migration processes like water washing and biodegradation, and analyzing the heavy fraction of crude oil, which bears the most chemical resemblance with the kerogen that produced the present-day hydrocarbon. Prior to these laboratory analyses, downhole fluid samples should be subject to a chain of custody procedure, consisting of reconditioning the sample to the same conditions of pressure and temperature prevailing during the acquisition of the sample in the downhole, analysis of a subset of the fluid sample using the same techniques employed in the downhole environment, and comparison of the laboratory and downhole results to determine the quality of the sample, i.e. preservation of the chemical composition.
Downhole fluid analyses (DFA) as fluids are withdrawn from a reservoir using VIS-NIR spectroscopy, NMR, gas chromatography and other sensors, in situ fluid analyses with NMR, and pressure and temperature gradient measurements can provide the following information: (a) fluid composition, compound classes (saturates, aromatics, resins, asphaltenes, paraffins, naphtenes), density, viscosity, (b) fluid composition and pressure variations between stratigraphic units. This provides information on the level of compartmentalization of the accumulation; (c) fluid composition variations within the same layer. Fluid composition variations could be observed within the same layer in thick intervals and when drilling along a reservoir (geo-steered wells). Special chemical analysis in the laboratory can provide more detailed information on the nature of the hydrocarbons: (a) principal chemical classes present in the sample; (b) gas isotopes (c) presence of heavy metals, etc. Analysis of the chemistry of larger molecules (the heavy fraction of crude oil) can provide information concerning: (a) similarity between fluids analyzed at different spatial locations; (b) chemical composition of the precursor material (kerogen)
All the foregoing provide information on the level of mixing of hydrocarbon species within an accumulation, on the possible origin of the hydrocarbons, on the level of hydrocarbon maturation, and whether the hydrocarbon has been subject to biodegradation or water washing, all of which are important components of basin modeling.
Fluid analysis in the reservoir and laboratory analyses have been used in reservoir exploration/appraisal to help determine the reservoir structure. Fluid pressure data are used to assess the areal and vertical continuity of specific reservoir units. A fluid model that uses the fluid features observed as input can be combined with the geological model of the reservoir. Since field appraisal and development can occur at a faster pace than exploration, it is desirable to be able to predict fluid properties at the locations of wellbores expected to be drilled to facilitate real time analysis and continuous update of the geological model.